Offshore oil and gas field developments are capital-intensive projects that require extensive facilities to drill, produce and transport the hydrocarbon from the reservoir to the processing plant. Determining the site, number and size of these facilities are amongst the most important decisions impacting a project's success. Here, we present a novel strategy to assist in these decisions by combining a stochastic optimization routine with a Virtual Reality (VR) Aided Design. The model uses a discrete-network optimization algorithm that employs a Monte Carlo Markov chain to explore feasible configurations that minimize the development's investment. It integrates the optimization with a state-of-the-art VR environment to allow the engineer to both monitor the progress of the optimization and help guide the field development in real time.
We present results illustrating how the approach can be employed in field developments to connect well targets to processing facilities. The model determines the optimum location, size and number of offshore well-head platforms, tie-in facilities, well paths and pipeline routes. It incorporates critical technical considerations for the design of drilling paths (e.g. dog leg severity) and surface facilities (e.g. water depth). The model has been applied to real data from offshore field developments in the North Sea and the Gulf of Mexico. Results including the investment value and optimum configuration are shown and supplemented with graphics from the VR environment. The VR technology enables a novel approach to optimize the development. The immersive platform lets the user not only visualize the field, it is also capable of providing real-time interaction with the computer-generated design. This allows the integration of engineering intuition and experience to enhance the development and eliminate infeasible or unfavorable configurations.
Where the natural drive mechanisms are inadequate, water-injection is commonly employed to supplement reservoir energy and improve sweep efficiency in conventional oil fields. In such applications, there is usually a strong positive correlation between field performance and injectivity/longevity of the water injectors. However, injectors are vulnerable to impairments, which can result in gradual injectivity decline and catastrophic failure. Therefore, robust field management and business planning require a good understanding of the impairment mechanisms of water injectors in general and, more important, reliable predictions of their injectivity behaviour and active lifetimes.
Following a review of common impairment mechanisms, this paper highlights the complexity and uncertainties of injector failure. It then exploits the two major impairment mechanisms of water-hammer and deep-bed filtration (DBF) to develop simple semi-empirical mathematical models for predicting the time-to-failure of vertical and slightly deviated water injectors. While water-hammer mobilises solid particulates native to the formation and deposits same in the wellbore, DBF entails external particulates suspended in the injection water and deposited in the reservoir. The mechanisms and impacts of these independent sources and deposition of formation-damaging particulates are covered.
Among other findings, sensitivity tests performed on the proposed models using realistic input data provide important insights into the mitigation and management of injector impairments caused by water hammer and DBF. To enhance the performance and longevity of water injectors, this study shows that these impairments can be mitigated through practical strategies such as (i) provision of long sumps (rat holes) as part of well completions; (ii) minimising the frequency and duration of emergency shutdown; and (iii) minimising the concentration of solid particulates entrained in injection water.
Finally, given the almost inevitability of injector degradation, it is recommended that realistic forecasting of oil and gas production associated with waterfloods should always account for potential injectivity decline and possible failure of applicable water injectors.
Ukaonu, Cyril (First Exploration & Petroleum Development Company) | Odubanjo, Teleola (First Exploration & Petroleum Development Company) | Lawal, Kazeem A. (First Exploration & Petroleum Development Company) | Eyitayo, Stella I. (First Exploration & Petroleum Development Company) | Ovuru, Mathilda I. (First Exploration & Petroleum Development Company) | Anyadike, Emeka (First Exploration & Petroleum Development Company) | Matemilola, Saka (First Exploration & Petroleum Development Company)
Sandstone formations that have potential to produce sand during the life of the well account for a significant fraction of global recoverable volumes of oil and gas resources. The economics, environmental and safety implications of sand problems are critical enough to justify good knowledge of the potential for sand failure and production. Reliable evaluation of potential sand production is required to identify the needs for and the specification of sand-exclusion equipment during the project execution phase.
To address these challenges, this paper presents a simple workflow that is premised on the petro-elasticity of the formation. Specifically, the proposed workflow uses cross plots of compressional sonic logs and density logs on reservoir-by-reservoir and well-by-well basis. From a petro-elastic standpoint, compressional sonic logs contain information on travel time required for sound waves to travel through the subject formation. The fundamental relationship between formation compaction (strength) and porosity has been explored to establish the trend of compaction, hence vulnerability of a sandstone formation to failure.
In illustrating the applicability of the proposed concepts and workflow, some field examples from the Niger Delta are presented. Using wells with known history of sand failure and production, the workflow has been applied retroactively. The methodology presented is very useful for establishment of a quick screening sand control requirement. From a qualitative standpoint, it is found that the performances of the proposed workflow are in reasonable agreement with the history of sand failure and production in the example wells.
Performance of a new three-phase (3-P) flow measurement system is presented using multiphase flow loop data. The system consists of two currently available products: an optics-based flowmeter and a near-infrared (NIR) water-cut meter. The measurement capability and performance of a combined system comprising two robust and field-proven technologies under realistic flow conditions is demonstrated for the first time. The new 3-P flow measurement system represents a viable alternative for subsea multiphase flow measurement and can also be used on offshore platforms, onshore as well as downhole, in single-zone or multizone applications.
The flowmeter system relies on three main measurements: bulk velocity and sound speed measured by the optics-based flowmeter, and water-cut measured by the water-cut meter. The velocity measurement is a robust measurement based on turbulent flow and is not affected by upstream flow conditions. The water-cut measurement is based on NIR absorption of water and oil molecules, and therefore, is immune to water salinity and the presence of gas (such as free gas, gas in solution, and oil foaming). Total flow rate is calculated using the bulk velocity measurement; liquid holdup and density of the mixture are obtained by introducing the mixture sound speed and the water-cut measurements into a flow model.
The results of the multiphase flow loop test demonstrated that the new flow measurement system is capable of resolving total volumetric flow rates as well as phase volumetric flow rates in a broad gas-volume-fraction (GVF) band. Furthermore, mixture density can be successfully calculated from the flow model and, as a result, the mass flow rates can also be determined. The test data also confirm that the water-cut measurement is not affected by foaming issues and associated density variations. The test results are discussed in detail in the paper.
The new flow measurement system offers several advantages. The flowmeter can be installed in any orientation and does not require recalibration. Its nonintrusive and fullbore features mean no permanent pressure loss, and high resilience to erosion and corrosion. The nonnuclear water-cut meter measures water cut in the broad GVF spectrum and is not affected by challenging flow conditions, such as slug flow. Installed inside a wellbore, an optics-based flowmeter can provide reliable flow measurement for the life of that well with no significant drift in signal.
A new downhole optical Venturi flowmeter (OVFM) was developed that makes use of world's first optical differential pressure sensor (ODPS) and an optical pressure/temperature gauge. The use of Venturi flowmeters for downhole applications is not common because of the short life span of the associated electronics in the challenging downhole environment. The OVFM may therefore represent a more reliable solution for downhole applications when compared to its electronic versions.
The heart of the OVFM, the ODPS sensor, was developed between 2007 and 2014 as a part of a downhole multiphase flowmeter program that required differential pressure (Δ
The results showed that the OVFM is in excellent agreement with the reference flow rates for single-phase, wet-gas, gas-rich/liquid, and liquid-rich/gas flows. By dynamically adjusting the density and viscosity of the fluid at the measured pressure and temperature (
The OVFM represents a novel technology because the ODPS sensor is the first and only optical Δ
Permanent surface and downhole measurement technologies have advanced considerably in terms of availability, reliability, performance and costs, and are increasingly deployed for real-time monitoring of wells and equipment. Permanent downhole sensors are used to measure pressure, temperature, flow rates, fluid phases and to reflect operating conditions in wellbores. Surface sensor systems provide real-time measurements of pressure, temperature, fluid phases and flow rates that need to be integrated for analysis. The resulting large volume of data has created challenges in data management, evaluation and analysis. It is important that production analysts have access to workflows and tools that provide real-time efficient and effective visualization and analysis. The optimal approach is to perform the visualization and analysis of data in real time, or near real time, to provide analysts with actionable information for timely and accurate decision making.
Permanent downhole gauges are used for monitoring reservoir drainage, injection efficiency, well-completion hardware performance, and downhole pump performance. Some of the resulting benefits include reduced operational costs, improved safety, and properly monitored well integrity. Several onshore and offshore case studies are discussed to demonstrate application of real-time measurements coupled with visualization and analysis techniques to also achieve improved artificial lift performance, reduced operating costs, and manage production. The value of the information obtained from downhole permanent gauges and surface measurements are justified as evidenced by the growing number of operators relying on real-time permanent gauges.
This paper reviews technologies that are used to monitor and manage equipment and production in oil and gas wells. It explains that the realized value of permanent monitoring depends on an efficient workflow for collection, evaluation, and analysis.
Each year, the Society of Petroleum Engineers (SPE) confers its highest honors and awards on members whose outstanding contributions to SPE and the petroleum industry merit special recognition. Recipients of this year’s international awards will be recognized at the Annual Reception and Banquet on Tuesday, 29 September, and Distinguished Members will be honored at the President’s Luncheon, Wednesday, 30 September during the 2015 SPE Annual Technical Conference and Exhibition in Houston. Honorary Membership is conferred on individuals for outstanding service to SPE and/or in recognition of distinguished scientific or engineering achievement in fields encompassed in SPE’s technical scope. Honorary Membership is the highest honor that SPE confers on an individual and is limited to 0.1% of SPE’s total membership. He started working for Phillips Petroleum in Odessa, Texas, in 1978. In 1980, he joined Rogaland Research (now the International Research Institute of Stavanger) and was central in building the Ullrigg, a drilling research rig. Later, he worked for Saga Petroleum, where he developed the Norwegian well design manual. He also helped develop an undergraduate petroleum engineering program at the University of the Faroe Islands. Aadnøy has published many conference and journal articles and several books such as Modern Well Design and Petroleum Rock Mechanics: Drilling Operations and Well Design, and was one of the editors of Advanced Drilling and Well Technology. He has served as a board member in the SPE Stavanger Section, on the JPT Editorial Committee, and on the planning committees of many SPE conferences. Aadnøy has been a reviewer for SPE Journal, SPE Drilling & Completion, and the Journal of Petroleum Science and Engineering. He has given many SPE short courses around the world, mainly on the topic of modern well design. He was a recipient of the 1999 SPE Drilling Engineering Award.
Lawal, Kazeem A. (Shell Nigeria Exploration & Production Company) | Okosun, Joshua (Shell Nigeria Exploration & Production Company) | Olatunji, Idris (Shell Nigeria Exploration & Production Company) | Okonkwo, Paulinus (Shell Nigeria Exploration & Production Company) | Horsfall, Ipalibo (Shell Nigeria Exploration & Production Company) | Adenuga, Ademola (Shell Nigeria Exploration & Production Company) | Ogunsina, Oluseye (Shell Nigeria Exploration & Production Company) | Ekebafe, Abraham (Shell Nigeria Exploration & Production Company) | Mbanefo, Edith (Shell Nigeria Exploration & Production Company) | Tendo, Fidelis (Shell Nigeria Exploration & Production Company) | Pokima, Sophie (Shell Nigeria Exploration & Production Company) | Bapoo, Saeed (Schlumberger Ltd)
To minimise well-count, sustain high injectivity and enable high offtake rates from the associated oil producers, cased-hole frac-pack water injectors in deepwater fields are often operated at relatively high injection rates. However, continuous injection at high rates (velocities) may displace the proppants in the sand-control system, increasing the vulnerability of such injectors to impairments by fines invasion. To mitigate this impairment mechanism, a new fibre-based product (interconnected fibre network) was recently introduced for locking proppants in-place. Although the product was extensively tested in the laboratory prior to its release, its field performance and impacts on injectivity remain uncertain.
To improve the reliability and longevity of a critical frac-pack water-injection well in a giant West-Africa deepwater oilfield, this proprietary product was recently deployed. Being the first field application in the exploration-and-production industry, this case-study presents an opportunity to validate the results of prior numerical and laboratory experiments while identifying relevant improvement areas for future developments and field applications. Specifically, the impacts of this product on well injectivity and other performance indicators were investigated.
Within 6 months of start-up, the well injected ca. 7 MMbbl of treated seawater and surveillance data acquired. Although this fibre-reinforced cased-hole frac-pack injector is still at relative infancy, this paper presents initial insights gained from managing the well. For the current evaluation, the surveillance techniques employed include the Hall-plot and deep-bed filtration analysis, complemented by step-rate, injectivity and pressure-transient tests. Among other findings, the performance of this well is generally comparable to the conventional (unreinforced) frac-pack injectors completed in an analogue reservoir in the same field.
To a reasonable extent, this pioneering case-study allays the pre-installation concerns that the product would hamper injectivity. The present observations notwithstanding, there remain some key uncertainties and challenges, which are potentially reducible as more statistically significant performance datasets become available from this field and elsewhere. It is too early to conclude from available data that the fibre-reinforced frac-pack performs better than the (previously used) non-fibre-reinforced frac pack injectors in this field.
High injection rates in water injectors leads to mobilization of particles in unconsolidated formations and creates preferential flow paths within the porous medium. Channelization in porous medium occurs when fluid-induced stresses become locally larger than a critical threshold (rock stress); grains are then dislodged and carried away, hence porosity and permeability of the medium will be altered along the induced flow paths. Additionally, rapid shut-ins result in pressure imbalance between the wellbore and formation. Flowback of the particles results in sand accumulation, and consequently loss of injectivity, which is a common problem in unconsolidated formations like the ones in deep water Gulf of Mexico. Experimental studies have confirmed the presence of dependent and independent flow patterns; however, there is no integrated model to describe flow patterns and predict probable issues for water injection at the reservoir scale. The objective of this study is to provide a model for a channel initiation/propagation during injection and flowback in injection wells. A finite volume model is developed based on multiphase fraction volume concept that decomposes porosity into mobile and immobile phases where these phases change spatially and evolve over time that leads to development of erosional channels in radial patterns depending on injection rates, viscosity, magnitude of in situ stresses and rock properties. The model accounts for both particle releasing and suspension deposition. The developed model explains injectivity change with injection rates observed in unconsolidated reservoirs.
This paper takes a novel approach towards managing the architecture and protocol of injection/production system. The shut-in valve positioning and time of valve closure control the amplitude and frequency of pressure waves generated during shutdowns. The proposed approach provides the means for mitigating negative impact of water hammer on the integrity of near wellbore region and the intensity of cross-flow. It is based on a comprehensive model of fast wellbore transients (water hammer) generated by routine or emergency shutdown of injector or producer and interacting with a near wellbore reservoir region. The modeling handles the conventional transient pipe flow hydraulics coupled with the transient reservoir flow. The decompression wave created by shutting down an injector interacts with the near wellbore region and may induce a transient flow back from reservoir creating a risk of mechanical damage and sand production. The compression wave created by shutting down a producer may induce repeated injection pulses. In both cases, multiple cross-flow phenomena can be triggered between formation layers and wells interconnected within the injection or production system. The analysis of these transient phenomena helps to potentially quantify the mechanical damage, which may be induced in near wellbore reservoir region, and assess the potential damage risk associated with produced solids.